High power density combined cycle power plant

Abstract

A system and method for increasing the specific output of a combined cycle power plant and providing flexibility in the power plant rating, both without a commensurate increase in the plant heat rate, is disclosed. The present invention demonstrates that the process of upgrading thermal efficiencies of combined cycles can often be accomplished through the strategic use of additional fuel and / or heat input. In particular, gas turbines that exhaust into HRSGs, can be supplemental fired to obtain much higher steam turbine outputs and greater overall plant ratings, but without a penalty on efficiency. This system and method by in large defines a high efficiency combined cycle power plant that is predominantly a Rankine (bottoming) cycle. Exemplary embodiments of the present invention include a load driven by a topping cycle engine (TCE), powered by a topping cycle fluid (TCF) which exhausts into a heat recovery device (HRD). The HRD is fired with a supplementary fuel or provided an additional heat source to produce more energetic and / or a larger quantity of the bottoming cycle fluid (BCF) which is used to power a bottoming cycle engine, (BCE) which drives a load (potentially the same load as the topping cycle engine). Energy contained in either the TCF or BCF is used to power the TCE and BCE respectively, but these fluids, and / or their respective engine exhausts, may also be used to support a wide variety of cogeneration applications.

Description

PARTIAL WAIVER OF COPYRIGHTAll of the material in this patent application is subject to copyright protection under the copyright laws of the United States and of other countries. As of the first effective filing date of the present application, this material is protected as unpublished material.However, permission to copy this material is hereby granted to the extent that the copyright owner has no objection to the facsimile reproduction by anyone of the patent documentation or patent disclosure, as it appears in the United States Patent and Trademark Office patent file or records, but otherwise reserves all copyright rights whatsoever.Not ApplicableREFERENCE TO A MICROFICHE APPENDIXNot ApplicableThis invention relates generally to combined cycle power plants that may or may not incorporate cogeneration into their cycle. As will be demonstrated by the following disclosure, the increasing need for more energy efficient and environmentally friendly methods of generating power has prom...

AI Technical Summary

Benefits of technology

3. Reduce installed cost of the power plant such that the debt service is substantially reduced and that financing by a bank or other lending institution is much easier for the owner.

21. Minimizing air consumption, emissions of criteria pollutants, and heat rejection to the atmosphere, but providing these environmental benefits with lower cost than the conventional combined cycles.

Problems solved by technology

However, there are limits that are imposed in these designs.

These stresses impose limits on the manufacturer's ability to produce this equipment, or economic limitations on the feasibility of producing this equipment.

In addition, above 3206 psia, steam no longer can coexist as both water and steam.

These HRSGs are typically very large and heavy pieces of equipment with literally miles of tubes inside.

Therefore, conventional steam fed feedwater heaters are not typically employed in combined cycle applications.

1. Steam cycle efficiencies are much lower than those of conventional steam power plants.

2. Multiple evaporator sections are required to maximize heat recovery. This results in increased equipment and maintenance costs.

3. Multiple evaporator sections require the plant operators and control systems to monitor and control all boiler (evaporator) drum levels.

4. The HRSGs with the multiple sections are very large, require large amounts of infrastructure building volume, large amounts of floor space, and large foundations to support the weight of the HRSG.

5. The HRSGs are expensive (approximately $10 million for a HRSG that recovers exhaust gas heat from one GE Frame 7 GT).

6. Maintenance increases with the number of components, evaporator sections, controls, and other devices.

7. Low-pressure steam (steam other than the highest pressure steam) has much less ability to produce power in the ST than higher pressure steam.

8. Partial load, off design operation, and other conditions besides the design conditions typically have reduced heat recovery and lower cycle efficiencies.

9. Increased amounts of tubing in the HRSG to enhance heat recovery add flow restriction to the exhaust gases from the GT and this increased back pressure decreases GT output and efficiency.

Gas turbine exhaust temperatures are not sufficient to produce some of the elevated steam conditions now used in advanced steam cycles 600.degree. C. which is equivalent to 1112.degree. F.

Balancing problems in the reheat lines with multiple GTs (typically three or more) make it difficult to utilize large STs in combined cycle power plants in the prior art.

Another disadvantage of the combined cycle application is partial load (part load) operation.

Part load operation reduces the efficiency of the GT, thus reducing the efficiency of the entire combined cycle plant. FIG. 7 illustrates a typical curve for a large modern GT with inlet guide vanes (IGVs) to modulate inlet airflow.

For GTs without IGVs, this decay in performance would be even more pronounced.

Note that providing this increase in part load efficiency occurs as a result of higher equipment costs.

The prior art has yet to solve the efficiency problem without the addition of more equipment that increases the overall power plant costs.

Therefore, supplementary firing of the HRSG is considered by the manufacturers to be a means to obtain more output, but with a penalty on efficiency.

No technique has been shown in the prior art to eliminate this heat rate penalty associated with supplemental firing.

However, operation at these high levels of ST / GT output are typically short in duration to meet peak power demands, and long term operation at these ratios is not economical.

Therefore, conventional combined cycle power plants that are designed with ST / GT ratios approaching unity do not operate predominantly as Rankine cycle power plants, but do so only to satisfy temporary peak plant loads, and do so with a significant efficiency penalty at all operating conditions.

Therefore, the GT is susceptible to performance decay if the compressor does not maintain optimum efficiency.

Therefore, it can be readily seen that small decreases in efficiency for the GT compressor lead to large decreases in efficiency and output for a GT.

This efficiency decay is largely a result of worn clearances in the compressor and erosion of the compressor blade tips.

However, this is a costly and time consuming repair, and would probably only be done at major inspections, which are scheduled approximately every four years for modern GTs.

Therefore, plant owners and operators will need to plan on this performance decay between major overhauls of the GTs.

However, with gas turbines being production line items, and combined cycles being primarily gas turbine based power plants, to achieve the highest efficiencies and best capital cost, a utility and / or power developer can no longer specify just their plant output, but must find the best fit for their needs from the available combined cycle offerings from the various manufacturers.

This implies that in certain circumstances the equipment complement for a given power plant installation will not be optimal because of constraints placed on plant equipment configurations by the current state of the art.

Next to fuel costs, the largest cost for a combined cycle plant is typically debt service.

One dilemma that faces power plant owners and utilities is the proper selection of power plant capacity.

Selecting a plant that is too small results in power shortages, brownouts, and / or the need to purchase expensive power from other producers.

Selecting a plant that is too large results in operation at lower efficiency during part load and increased capital cost per kWh produced.

In many situations the problem faced by power plant developers is the need to provide for peak power needs and temporary demand loading.

Typically in the summer months during peak hours on the hottest days is the most challenging time for power producers to meet the system load.

For example, in the early summer of 1999, power shortages in the Northeast United States have caused concern for the system's ability to meet peak power demands.

However, even much greater capacity costs have been incurred, as reported in POWER MAGAZINE, (ISSN 0032-5929, March / April 1999, page 14): "Reserve margins are down nationwide from 27% in 1992 to 12% in 1998, according to Edison Electric Institute, Washington, DC, because deregulation uncertainty has caused capacity additions to stall.

However, providing peak power will not be lucrative if the power plant owners have to pay for this capacity, pay the debt service, and yet make revenue on this extra capacity only during a few days of the year.

From this graphic it can be surmised that it would never be profitable to design a power plant to peak loading conditions, as they occur less than 10% of the time.

Since prior art power plants are generally incapable of wide variations in peak power output, the only practical option available for present power providers is to purchase power over the electrical grid during times of peak power demand.

One significant problem with the prior art is that the plant capacity is in general a relatively fixed and narrow range of power generation operation.

There are several major problems with this mode of providing for peak power by rerouting remotely generated power plant capacity.

First, there exist losses associated with transmission of power from remote sites to the place where the electrical power is being demanded.

For example, a hot summer day in New York City may require diversion of power from Canada or the western United States, resulting in significant line losses during transmission.

Second, there is a reliability drawback in purchasing power from distant parts of the grid during periods of peak load.

While it is possible to redistribute power, the tradeoff is instability in the electrical grid.

What can happen is that small failures in remote parts of the grid can cascade throughout the grid to either cause additional equipment failures or cause instability in the grid voltage.

Thus, while purchasing power from remote power plants may alleviate some local reliability problems with respect to providing electric power, the tradeoff is an overall reduction in the reliability of the entire electrical grid.

Thus, relatively insignificant events in remote parts of the country can cascade throughout the electrical grid and result in serious electrical failures in major metropolitan areas.

It is significant to note that the prior art limitations on plant output during peak load generally preclude local generation of the required peak power demand.

This forces traditional power plants to purchase power from remote power plants at a substantial (10.times. to 250.times.) price penalty.

As the plant size grows, the amount of equipment increases, and as the complexity of the equipment increases, O&M costs also increase.

In the quest for higher efficiency, more elaborate and expensive technology is being utilized in the gas turbines.

The maintenance costs associated with exotic new materials, intricate blades, and complex hardware is projected to be significantly more expensive than the slightly less efficient, proven gas turbine hardware and associated plant designs.

This constitutes inventory that has high costs in terms of both unused capital and taxes.

However, if the power plants are not located in close proximity to major natural gas pipelines, the lower pressure natural gas may have to be compressed to a sufficient pressure to be used in the GT.

This need for higher pressure natural gas requires expensive natural gas compressors that are critical service items (the plant cannot operate without them).

These natural gas compressors require frequent maintenance and also consume parasitic power (the power to run the compressors reduces the net power available from the power plant to the grid).

These systems will all add greatly to the installed cost and O&M costs.

In addition, to date, boiler tubes, HRSGs and STs have not demonstrated long term reliable operation at elevated temperatures above 1150.degree. F., and HRSGs with diverters and natural gas reformers are as yet unproven in the marketplace.

GT engines consume large quantities of air.

This adds to the O&M costs and increases plant downtime (time when the plant is out of service and unavailable to produce power).

In addition, the air consumed by the GT is discharged to the HRSG and then exhausted to atmosphere.

This represents an efficiency loss as the HRSG exhaust temperature is typically about 180.degree. F.

In addition, this airflow serves to heat the atmosphere and contribute to local air quality problems.

Combined cycle power plants are very clean producers of power compared to other conventional methods, but are typically plagued by one criteria pollutant, nitrous oxides (NOX).

ut. However, at partial load, GT NOX emissions are typically increa

tion. This increases O&M costs, and can be significant to the point where, at the plant design stage, the desired GTs cannot be used due to high emission levels at part load opera

mption. GTs require large amounts of air, and the more air that is consumed, the more potential there is for em

This blowdown must be discharged into rivers, streams, etc. and as such requires water permits that may be difficult and time consuming to obtain from regulatory authorities.

None of these patents, however, provide control of heat transfer in the HRSG.

This method, however, does not provide comprehensive control, but only a means for recovering low temperature waste heat.

None of the aforementioned patents has devised a method to control the exhaust gas temperature of the HRSG to its optimum temperature

However, this is detrimental to overall plant efficiency.

"Supplemental firing of the heat recovery steam generator can increase total power output and the portion of the total power produced by the steam turbine, but only with a reduction in overall plant thermal efficiency."

For large central power plants, this factor equates to significant added fuel costs.

In addition, operation at part load on the GT typically increases the emission levels for the most difficult criteria pollutant, NOX.

This change in flow upsets the heat transfer in the HRSG since this device is constructed with fixed heat exchange surface area.

This phenomenon, as well as reduced GT efficiency, contributes to poorer overall efficiency at part load operation.

If part load operation changes temperatures in the HRSG significantly, this could lead to ineffective operation of the SCR.

Besides inlet pressure and temperature limitations, another common limitation for the steam turbine (ST) is the exhaust end loading.

However, due to mechanical limitations (centrifugal force), once the largest available blade volumetric limits are reached, more sections and more blades must be added to the exhaust end of the ST to accommodate this flow.

This adds to the installed cost and increases the real estate requirements of the ST.

Overall, this ST arrangement is less efficient than conventional steam plant STs since the HP and IP sections have low volumetric flows.

However, available real estate for a large combined cycle power plant may be difficult and expense to attain in these areas.

The drawback is that the site may lack the necessary real estate for a combined cycle repowering project.

Public acceptance is becoming increasing difficult for many utility power plant projects.

Factors such as noise, traffic increase, unsightliness, pollution, hazardous waste concerns, and others contribute to public disapproval of power plants in close proximity to populated areas.

No attention is currently being given to the issue of whether plants may be redesigned to consider the ancillary issues associated with the public acceptance of the plants themselves.

Since the combined cycles in the prior art are primarily GT based, their efficiency levels are very susceptible to GT performance decay, a phenomenon in which the efficiency of the GT degrades substantially (2% to 6%) within only a year or two of operation.

This can be a significant factor in the cost of fuel as the overall combined cycle efficiency also degrades as the GT performance decays.

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